William Lawson Director, Environmental Department

1407 West North Temple, Suite 330 Salt Lake City, Utah 84116 801.220.4581 (Office)

801.220.2094 (Fax)

units. January 29, 2009

Mr. David Finley Wyoming Division of Air Quality Herschler Building 122 W. 25 th Street Cheyenne, Wyoming 82002

Re: PacifiCorp -- Wyoming BART Determinations and Regional Haze SIP

Dear Mr. Finley,

You have requested that PacifiCorp provide additional support regarding its proposed BART determinations for NO x emissions at Jim Bridger units 1 – 4 and Naughton unit 3. 1 The information contained in this letter is intended to elaborate on PacifiCorp’s BART analyses, which already have b een filed with WDAQ for these



### I. Executive Summary

This letter focuses solely on the proper BART emission limit for NO x at Naughton unit 3 and the Jim Bridger units. PacifiCorp’s individual BART applications for each of these units contain a proposed BART emission limit which can be achieved through the installation of combustion controls such as low-NO x burners (LNB) and overfire air (OFA). This is appropriate and consistent w ith the guidance and requirements set forth in “Appendix Y” of EPA’s Regional Haze Regulati ons and Guidelines for Best Available Retrofit Technology; Final Rule (“Regional Haze Rules”), as those are incorporated into Wyoming’s state regulations. This is al so consistent with the preamble which accompanies Appendix Y and the Regional Haze Rules (the “Preamble”). See 70 FR 39104.

Appendix Y references “presumptive BART” emission rates which vary based on boiler design and coal type. To the ex tent the presumptive BART NO x emission rates are relevant to Naughton unit 3 and th e Jim Bridger units, it is impor tant to note that the coal burned at these units is more comparable to bituminous than subbituminous (as the coal classification relates to NO x emissions). Correctly assuming that these units burn coal

1 This letter does not address any of the other P acifiCorp BART-eligible units in Wyoming nor is it intended as a comprehensive list of comments PacifiCorp may choose to make in regard to WDAQ’s upcoming BART determinations for the PacifiCorp units.Wyoming Division of Air Quality January 29, 2009 Page 2

2 with bituminous-like NO x emissions leads to a presumptive BART emission limit for NO x of 0.28 lb/MMBtu. This presumptive BART emission limit, however, is not the end of the analysis for any of the units, but only se rves as a guide against which the calculated BART emission limit can be compared.

Based on a variety of other factors as described herein and in the underlying BART applications, PacifiCorp continues to r ecommend that assigning a calculated 30-day rolling average BART emission limit for NO x of 0.26 lb/MMBtu for the Jim Bridger units is appropriate, including the installation of LNB and OFA as the proper BART control technology. Also, assigning a calculated 30- day rolling average BART emission limit for NO x of 0.35 lb/MMBtu for Naughton unit 3 lik ewise is appropria te, including the installation of LNB and OFA as th e proper BART control technology.



### II. Background

In its BART applications for each unit covered by this letter, PacifiCorp and its consultant worked closely with WDAQ staff before submitting detailed BART engineering analyses for Naughton unit 3 an d the Jim Bridger units. These analyses resulted in the proposed BART NO x emission limits and cont rol technologies listed below in Table 1:

Table 1

Unit Proposed Rate Proposed Control Technology

Naughton 3 0.35 lb/MMBtu tune existin g LNB and over-fire air system Jim Bridger 1 0.26 lb/MMBtu add LNB with separated over-fire air Jim Bridger 2 0.26 lb/MMBtu already adde d LNB with separa ted over-fire air Jim Bridger 3 0.26 lb/MMBtu add LNB with separated over-fire air Jim Bridger 4 0.26 lb/MMBtu add LNB with separated over-fire air

In lieu of the above proposed rates, some may argue that WDAQ should instead impose the presumptive BART rate (found in Appendi x Y) for tangentially-f ired boilers burning subbituminous coal. This rate is 0.15 lb/MMB tu. To the extent this presumptive BART rate is applied, some may argue further th at WDAQ should require the installation of SCR as the appropriate BART control te chnology in order to achieve this NO x emissions rate. As explained below, however, neit her the facts nor the applicable BART requirements support these arguments.

To the contrary, as noted in PacifiCorp’s BART applications, and as further explained herein: (i) applying the presumptive BART rate of 0.15 lb/MMBtu for subbituminous coal at these units is not appropriate; and (ii) requiring the installation of SCR at these units likewise is not an appr opriate BART control technology.Wyoming Division of Air Quality January 29, 2009 Page 3

3 

### III. Based on Proper Coal Classifi cation, the “Presumptive” BART NO x 

### Limit for Naughton Unit 3 and the Ji m Bridger Units is 0.28 lb/MMBtu

As explained herein and in the BART appli cations, to the extent a presumptive BART emission limit (as found in Appendix Y) is re levant, then the appr opriate presumptive BART limit for NO x at Naughton unit 3 and the Jim Br idger units is 0.28 lb/MMBtu.

Presumptive BART

The Preamble to the BART rules observes that “States, as a general matter, must require owners and operators of great er than 750 MW power plants to meet [presumptive] BART limits.” 2 70 FR 39104, 39131. The Preamble goes on to say, however that “a State may establish different requirements if the State can demonstrate that an alternative determination is justified based on consid eration of the five statutory factors.” Id. Specific to NO x emission limits, the Preamble notes that, “the NO x limits set forth here today are presumptions only; in making a BART determination, States have the ability to consider the specific characteristics of the so urce at issue and to fi nd that the presumptive limits would not be appropriate for that source.” Id at 39134.

By rule, Wyoming follows Appendix Y in determining the proper BART NO x emission limits for electric generating units (EGUs ). Wyo. Reg., Chap. 6, Sec. 9(c). The presumptive BART NO x emission limits listed in Appe ndix Y are “differentiated by boiler design and type of coal burned.” See 40 CFR Part 51, Appendix Y, IV.E.5. As noted above, the presumptive BART NO x emission limit (for EGUs with tangentially fired boilers) is 0.15 lb/MMBtu for coal ra nked as subbituminous. For coal ranked as bituminous, the presumptive BART NOx emi ssion limit (for EGUs with tangentially fired boilers) is 0.28 lb/MMBtu. 3 Id. EPA readily acknowledges th at these presumptive NO x emission limits are based on many assump tions and also that, if one of these assumptions does not apply to a particular unit, it may affect the cost-effectiveness of the presumptive limit. 4

2 The Jim Bridger power plant exceeds 750 MW in to tal capacity; the Naughton power plant does not.

3 Even though the Wyoming rules distinguish – based on the amount of generating capacity – between whether Appendix Y “shall” apply or be used merely as “guidance,” Appendix Y itself applies the same presumptive NO x emission limit regardless of facility generatin g size. “For coal-fired EGUs greater than 200 MW located at greater than 750 MW power plants and operating without post combustion controls [i.e., Jim Bridger units]. . . , we have provided presumptive NO x limits differentiated by boiler design and type of coal burned . . . . For coal-fired EGUs greater than 200 MW located at power plants 750 MW or less in size and operating without post-combustion cont rols [i.e., Naughton unit 3], you should likewise assume that these same levels are cost effective. You should require such utility boilers to meet the following NO x limits, unless you determine that an alternative control limit is justified . . . .” 70 FR 39171.

4 “The following NO x emission rates were determined based on a number of assumptions, including that the EGU boiler has enough volume to allow for installati on and effective operation of separated overfire air ports. For boilers where these assumptions are incorr ect, these emission limits may not be cost-effective.” 70 FR 39171.Wyoming Division of Air Quality January 29, 2009 Page 4

4 Coal Classification

Given the large disparity between the presumptive NO x emission limits for subbituminous and bituminous coals, it is very important to assign the proper coal classification when considering an individual un it. This is particularly true where, as is the case with Naughton unit 3 and the Jim Bri dger units, the use of one coal quality classification results in a signi ficantly different presumptive BART rate as compared to another coal classification.

In the Preamble, EPA recognized “that, unlike the methods for controlling SO 2 (which fall within a fairly narrow range of cost effectiveness and control efficiencies), the removal efficiencies and costs associated with the control techniques for NO x vary considerably, depending on the design of the bo iler and the type of coal used.” 70 FR 39104, 39134. Also, in that same section of the preamble, EPA recognized that “both cost effectiveness and post-control rates for NO x do depend largely on boiler design and type of coal burned

. ” Id. Therefore, to the extent presump tive BART rates are relevant; the BART analysis for Naughton unit 3 and the Jim Bridger units should carefully consider “the type of coal burned.”

Unfortunately, neither Appendix Y, the Pream ble, nor the Regional Haze Rules provide a standard or guidance to dete rmine the appropriate coal cl assification. Instead, Appendix Y simply presumes that coal types are easily classified with a clear distinction between the various coals. This pres umption, however, is not correc t and certainly should not be the sole basis for assuming that the presumptive NO x emission rate of 0.15 lb/MMBtu is applicable to Naughton unit 3 and the Jim Bridger units. Indeed, a review of the literature shows that coal types are only loosely defi ned along a sliding scale, meaning that no bright line distinction betw een types of coal exists.

Because coal classification is of such f undamental importance in selecting the proper presumptive BART rate, PacifiCorp included in its BART applications an explanation of why the coal burned at Naughton unit 3 and the Ji m Bridger units should be considered to be bituminous for the purpose of considering presumptive BART limits for NO x . In addition, PacifiCorp has attached to this letter a technical memorandum prepared by CH2M Hill entitled “Coal Qual ity and Nitrogen Oxide Formation” (the “Coal Quality Technical Memo”), which discusses this coal classification issue in more detail. The attached memorandum is intended to amplify similar information provided in the BART applications for these units.

Jim Bridger Units/Naughton Unit 3 Coal Classification

As the Coal Quality Technical Memo explains, a detailed analysis of the key coal characteristics that relate to the formation of NO x emissions supports the conclusion thatWyoming Division of Air Quality January 29, 2009 Page 5

5 the Jim Bridger units and Naughton unit 3 coal s should be considered as bituminous for the purpose of applying a presumptive BART NO x emission limit. This conclusion alone supports presumptive BART limits based on bituminous coal.

As an additional reason, and as explained in the Coal Quality Technical Memo, most coals from the Powder River Basin (“PRB” ) are classified as subbituminous C and demonstrate high-reactivity and low-NO x production characteristics. It is against this backdrop of already low NO x emissions typically associated with PRB subbituminous coal that EPA selected the very low presumptive NOx emission rate of 0.15 lb/MMBtu for tangentially fired boilers (like those at Naughton unit 3 and the Jim Bridger units) and assumed that this rate could be achieved by combustion controls like LNB and OFA. In reaching this conclusion, however, EPA assumed that PRB subbituminous C coals to represent the entire cl ass of subbituminous coals in use across the countr y since the PRB coals make up the largest share of such co als. However, there are other types of subbituminous coals that occur outside of th e PRB that are not as reactive and low NOx forming as the PRB coals. EPA’s general assumptions regarding NO x emissions and subbituminous coals, therefore, fail to recognize that non-PRB subbituminous coals could have higher NO x emissions than PRB subbituminous C coals. This, in turn, affects the feasibility and cost effectiven ess of the presumptive BART NO x emission limits (as stated in Appendix Y) for boilers using non-PRB subbituminous coal like Naughton unit 3 and the Jim Bridger units.

In other words, with NO x emissions from PRB subbituminous coal already low compared to other types of coal, EPA apparently believes it is a technologically easy and costeffective step to impose an even lowe r presumptive BART emission rate of 0.15 lb/MMBtu (for tangentially fired boilers), which can be achieved by adding combustion controls like LNB and OFA. However, for non-PRB subbituminous coals, it is not such an easy and cost-effective step because combustion controls t ypically will not be enough to control NO x emissions to this rate. In this light, EPA’s presumed feasibility and costeffectiveness falls apart because very expens ive and impractical post-combustion controls become part of the BART equation for certain subbituminous (non-PRB) coals.

The Coal Quality Technical Memo concludes as follows:

“For all these reasons, the [Naughton unit 3 and Jim Bridger units] coals . . . are more similar in their NO x formation potential to bituminous coals than to subbituminous coals such as PRB. Therefore, the presumptive BART limit that should be considered for the Jim Bridger [units] and Naughton [unit 3] . . . should be closer to 0.28 lb/MMBtu presum ptive BART limit rather than the subbituminous 0.15 lb/MMBtu limit.”

Considering the presumptive BART NO x emission limit for bituminous coal for Naughton unit 3 and the Jim Bridger units not only complies with the requirements ofWyoming Division of Air Quality January 29, 2009 Page 6

6 Wyoming law (including Appendix Y), but is more stringent than BART limits imposed on other Wyoming sources. 5

Coal Classification In Other States

The coal classification issue di scussed above in regard to pr esumptive BART limits is not unique to PacifiCorp’s units or the state of Wyoming. The State of New Mexico is addressing a similar issue concerning th e San Juan Generating Station (SJGS).

In New Mexico, the SJGS argues that it cannot meet the presumptive BART NO x emissions limit of 0.23 lb/MMBtu (for a dry bottom, wall-fired boiler) for subbituminous coal. Using this presumptive BART limit was problematic because the local New Mexico coal used by SJGS fit into a “gray area” between bituminous and sub-bituminous coal. See “Discussion of SJGS Coal Ranking for BART NO x Presumptive Limit Determination.” The SJGS coal was less volat ile, and has less oxygen and moisture, than the characteristics of PRB subbituminous co als used in developing the presumptive BART NO x emission limits under Appendix Y. Id. As the SJGS explains, “with respect to NO x combustion control performance, SJGS coal behaves more like a bituminous coal.” 6 Id.

The same can be said of the Jim Bridger un its and Naughton unit 3 coals. Therefore, if a presumptive NO x emissions limit is considered for a ny of these units, PacifiCorp urges WDAQ to take account of the applicable coal characteristics and properly assume that the Jim Bridger units and Naughton unit 3 coals are closer to bituminous in composition than subbituminous. This proper assumption, in tu rn, leads to the conclusion that if a presumptive BART NO x emission limit is considered for any of these units, it should be at the 0.28 lb/MMBtu rate presumed for bitumi nous coal. As explained in the following section, however, the calculate d BART emission rates note d in Table I above should control over the presumptive BART rates in any event.



### IV. The Five Factor Analysis Also Indicates SCR Is Not Appropriate

5 For example, Wyoming has proposed higher NO x emissions rates for other coal fired boilers in Wyoming. When making the BART determination for FMC’s Westvaco facility, Wyoming determined that a NO x emissions rate of 0.35 lb/MBTU was BART. See August 4, 2008 BART Application Analysis, AP 6045, pg. 30. Additionally, Wyoming approved a BART NO x emissions rate of 0.49 lb/MBTU for General Chemical’s two coal fired boilers at its Green River Works facility. See August 4, 2008 BART Application Analysis, AP 6046, pg. 26. PacifiCorp’s proposed “presumptive” BART limit of 0.28 lb/MBTU for the Naughton and Jim Bridger power plants is much lower than these sources.

6 The BART NO x emission limit proposed by the New Mexico Environment Department for the SJGS is 0.293 lb/MMBtu. This is consistent with the limit established in a consent decree concerning the plant which is unrelated to the BART determination. For information concerning SJGS BART issues, see http://www.nmenv.state.nm.us/aqb/ reghaz/documents/COMPLETEFinalDisc ussionofSJGSCoalClassificati onRevisi.pdfWyoming Division of Air Quality January 29, 2009 Page 7

7 Establishing the appropriate presumptive BART NO x emission limit as described above is only one considerat ion in making a proper BART determ ination. Indeed, if an analysis of the five statutory factor s supports a different emissions limit, then the presumptive BART rates take on a role only as a non-bi nding guide or marker for units like Naughton unit 3 and the Jim Bridger units.

Five Factor Analysis and Proposed BART Limits

As noted, the presumptive BART limits ar e exactly what they purport to be – presumptions that can be rebutted and m odified based on additional case by case information. In the Preamble, EPA states th at its “presumption accordingly may not be appropriate for all sources. As noted, the NO x limits set forth here today are presumptions only; in making a BART determination, States have the ability to consider the specific characteristics of the source at issue and to find that the presumptiv e limits would not be appropriate for that source

. ” 70 FR 39134. Appendix Y further explains that a state “may determine that an alternative control level is appropriate based on a careful consideration of the [five 

### ] statutory factors,” particularly for boilers where EPA’s assumptions related to NO x emissions rates are incorrect. See Appendix Y, IV.E.5.

PacifiCorp already has submitted a detailed five factor analysis for Naughton unit 3 and the Jim Bridger units in their individual BART applications. The final result of this analysis is a proposed BART emission lim it for NOx at Naughton unit 3 of 0.35 lb/MMBtu – higher than the presumptive BA RT limit of 0.28 lb/MMBtu. As for the Jim Bridger units, the result of the analysis is a NOx limit of 0.26 lb/MMBtu – lower than the presumptive BART limit. In each case; howev er, the proposed BART limits can be met by the installation of combusti on controls. Imposing lower NO x limits than PacifiCorp has proposed would require the installation of post-combustion controls such as SCR, which is contrary to applicable BART re quirements because the “cost of compliance” would be too high.

Cost of Compliance

Focusing on the cost of compliance factor, EPA assumes in the Preamble that approximately 75% of the EGUs would have BART NO x removal costs between $100 and $1,000 per ton, and that almost all of th e remaining EGUs could install sufficient combustion control technology for less than $1,500 per ton:

“The limits provided were chosen at leve ls that approximately 75 percent of the units could achieve with current combusti on control technology. The costs of such controls in most cases range from ju st over $100 to $1000 pe r ton. Based on our analysis, however, we conc luded that approximately 25 percent of the units could not meet these limits with current co mbustion control technology. However, our analysis indicates that all but a very few of these units could meet the presumptive limits using advanced combustion contro ls such as rotating opposed fire airWyoming Division of Air Quality January 29, 2009 Page 8

8 (“ROFA”), which has already been demonstr ated on a variety of coal-fired units. 7 Based on the data before us, the costs of such controls in most cases are less than $1500 per ton.” 70 FR 39135.

EPA’s assumptions regarding the cost of controls place Naughton unit 3 or the Jim Bridger units outside the scope of expected removal costs when considering the lower presumptive limit of 0.15 lb/MMBtu. As indicate d in the BART applications, these units can only meet this rate by installing SCR. Un der this scenario, the incremental control costs per ton would approach $4,000 per ton, we ll above the presumed control cost range included in the Preamble.

It is for this reason that EPA stated further in the Preamble that SCR generally is not cost effective for EGUs (except for cyclone boilers):

“We also analyzed the installation of SCRs at BART-eligible EGUs, applying SCR to each unit and fuel type. The cost -effectiveness was generally higher than for current combustion control technology except for one unit type, cyclone units. Because of the relatively high NO x emission rates of cyclone units, SCR is more cost-effective. Our analysis indicated th at the cost-effectiveness of applying SCR on coal-fired cyclone units is typically less than $1500 a ton, and that the average cost-effectiveness is $900 per ton. As a result, we are establishing a presumptive NO x limit for cyclone units based on the use of SCR. For other units, we are not establishing presumptive limits based on th e installation of S CR. Although States may in specific cases find that the use of SCR is appropriate, we have not determined that SCR is generally co st-effective for BART across unit types .” 70 FR 39135-36. (Emphasis supplied)



### V. LNB /OFA Are the Proper BART Control Technology; SCR is Not

Unlike SCR, LNB/OFA is the proper BART control technology for Naughton unit 3 and the Jim Bridger units.

A “BART” determination involves not only the se tting of an emissions limit, but also the selection of a particular emissions cont rol technology, or group of technologies, to achieve that limit. Wyoming’s BART rules refe r to this as “control equipment”, “control technology”, and “BART technolog y.” Wyo. Reg., Chp. 6, Sec. 9(e)(i)(E), Sec. 9(e)(iii) and (e)(viii). Regardless of the term used, and as explai ned above, the Preamble and other guidance are clear that LNBs and OFA are in tended to be the “BART technology” for the tangentially fired boilers su ch as Naughton unit 3, the Ji m Bridger units, and other similarly situated units.

7 The BART applications for Naughton unit 3 and th e Jim Bridger units explain why ROFA is not a workable alternative for those units.Wyoming Division of Air Quality January 29, 2009 Page 9

9 In the Preamble, EPA stated that, except for cyclone boilers, the “types of current combustion control technology options assume d include low NOx burners, over-fire air, and coal reburning.” 70 FR 39134; see also 39144 (“For all other coal-fired units, our analysis assumed these units will install current combustion control technology.”). In fact, in the Technical Support Document us ed to develop the presumptive BART NO x emissions limits, EPA explained that th e “methodology EPA used in applying current combustion control technology to BART-eligible EGUs” included applying “a complete set of combustion controls. A complete set of combustion controls fo r most units includes a low NO x burner and over-fire air.” See, “T echnical Support Document, Methodology for Developing NO x Presumptive Limits,” EPA Clean Air Markets Division, pg. 1 (dated June 15, 2005).

The Preamble identifies post-combustion controls for NO x , such as SCR and SNCR, as “BART technology” for only “cyclone” units. EPA made it clear that for “other units, we are not establishing presumptive limits based on the inst allation of SCR.” 70 FR 39136. Therefore, EPA’s presumptive “BART technol ogy” is LNBs and some type of OFA. EPA further elaborated in the preamble on the SCR costs, stating that although “States may in specific cases find that the use of SCR is appropriate, we have not determined that SCR is generally cost-effective for BART across unit types.” Id.

Other BART eligible sources in Wyoming ha ve determined that LNBs and/or OFA are “BART technology,” and that SCR would not be appropriate. For example, after additional analysis and study, Basin Electric re cently submitted its analysis that OFA was the appropriate BART technology for the Laramie River Stati on and that SCRs were not “BART” due to several factor s, including the high cost a nd relatively low visibility improvement. See Basin Electric/Laramie River St ation Refined BART Visibility Modeling, pages 13 and 14 (submitted July 24, 2008).

Similarly, the State of Wyoming also determin ed that LNBs and OFA were BART for the coal-fueled boilers at FMC’s Westvaco facil ity and at General Chemical’s Green River Works facility. See August 4, 2008 BART Application Analysis, AP 6045, pg. 30, and August 4, 2008 BART Application Analys is, AP 6046, pg. 26. All of these BART analyses reviewed SCR and SNCR, but none of them found that SNCR or SCR are BART for any of these facilities. Likewise, LNBs and OFA should be determined to be BART technology for PacifiCorp’s Jim Bridger and Naughton EGUs.

A recent survey of the western states indica tes that no states have mandated SCR or SNCR as “BART technology” for any EGUs. Fo r example, in Colorado’s recent BART determinations, Colorado recognized LNBs an d OFA (or some modification of the same) as BART for 14 different EGUs. See Colorado’s Air Quality Regulations, Part F, IV.D. In fact, consistent with PacifiCorp’s posit ion explained above, Co lorado believes that Appendix Y and the preamble do not allow post- combustion control, such as SCRs, to be considered at all as “BART technology.” In a letter addressing BART issues, Colorado’s Air Quality Division explaine d that “Colorado’s BART rule does not allow for post combustion NOx controls. This provision is based upon the preamble to the final EPAWyoming Division of Air Quality January 29, 2009 Page 10

10 BART rule and Appendix Y.” See January 11, 2008 letter to Vickie Patton from Colorado Division of Air Quality, pg. 3.

Additionally, the Oregon Department of E nvironmental Quality, in the August 20, 2008, BART determination for the Boardman pow er plant, found that SCR was not BART technology and stated that the “capital cost of [SCR] is 7 times that of new low NOx burners with modified overfire air system.” P acifiCorp’s BART applications confirm that SCR is not cost-effective or otherwise appr opriate for Naughton unit 3 or the Jim Bridger units. Therefore, Wyoming, like other western states that have considered the issue, should determine that BART technology fo r PacifiCorp’s Jim Bridger and Naughton power plants is LNBs and OFA, and not SCR or SNCR.



### VI. Conclusion

Based on a close examination of the charac teristics of coal burned Naughton unit 3 and the Bridger units, it is clear that the appropriate presumptive BART NO x emission rate for consideration at these units is 0.28 lb/MMBtu. The appropriate calculated NO x emission rate, however, is 0.35 lb/MMBtu for Naughton unit 3 (30 day rolling average) and 0.26 lb/MMBtu for the Bridger units (3 0 day rolling average). The appropriate control technology to achieve th ese rates is LNB and OFA.

Please feel free to contact us with any questions.

Sincerely,

William K. Lawson Director, Environmental Services

cc: Idaho PowerJMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 1

T E C H N I C A L M E M O R A N D U M 

## Coal Quality and Nitrogen Oxide Formation

PREPARED FOR: Bill Lawson/PacifiCorp

PREPARED BY: CH2M HILL

COPIES: Mike Jenkins/PacifiCorp

DATE: January 28, 2009

Nitrogen oxide (NO x ) formation in coal-fired boilers is a complex process that is dependant on a number of variables, including operating conditions, equipment design, and coal characteristics.



### Coal Combustion During coal combustion, NO x is formed in three ways: fuel NO x , thermal NO x , and prompt NO x . The dominant source of NO x formation (approximately 60 to 80 percent) is the oxidation of fuel-bound nitrogen (fuel NO x ). The amount of nitrogen contained in the coal directly impacts the amount of fuel NO x formed. During combustion, part of the fuel NO x is released from the coal with the volatile matter, and part is retained in the sol id portion (char). The nitrogen chemically bound in the coal is partially oxidized to nitrogen oxides (NO and NO 2 ) and partially reduced to molecular nitrogen (N 2 ). The release rate of nitrogen from the volatile fractions of the coal in the early stages of combustion and the release of nitrogen in the char portion later in the combustion process also impact NO x formation. In addition, the availability of oxygen in the combustion air to combine with nitrogen affects fuel NO x formation.

A smaller part of NO x formation (20 to 40 percent) is due to high-temperature fixation of atmospheric nitrogen in the combustion air (thermal NO x ). Thermal NO x can be affected exponentially by local temperatures and can be proportional to the square root of oxyge n availability.

A very small amount of NO x (less than 5 percent) is called “prompt” NO x . Prompt NO x results from an interaction of hydrocarbon radicals, nitrogen, and oxygen.

In a conventional pulverized coal burner, air is introduced with turbulence to promote good mixing of fuel and air, which provides stable combustion. However, not all of the oxygen in the air is used for combustion. Some of the oxygen combines with the fuel nitrogen to form NO x . Low-NO x burners (LNBs) in combination with overfire air (OFA) are designed to reduce the amount of air introduced during initial combustion when the volatiles are dri ven off and introduce air downstream to combust the remaining unburned char. Hence, LNBs result in less conversion of fuel-bound nitrogen to NO x and lower combustion temperatures limiting thermal NO x . In addition, lower temperatures and oxygen availability can reduce hydrocarbon reaction rates resulting in less prompt NO x formation. For retrofit of existing boilers, boiler size and configuration can limit the effectiveness of LNBs and O FA.COAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 2 

### Coal Ranking Coal ranking is a means of classifying coals according to their degree of me tamorphism in the natural series, from lignite to subbituminous to bituminous and on to anthracite.

The American Society for Testing Materials (ASTM) has developed a syst em for generally classifying coals based on their heating value, volatile content, moisture, re activity, and other properties. Eastern U.S. coals (high-volatile bituminous) tend to be high-rank fuels with high heating values and low moisture. At the other end of the spectrum, U.S. lignite coals tend t o be low rank, as their heating values are low, and moisture content high. Western U.S. c oals, like Powder River Basin (PRB), tend to be categorized in the lower rank Subbituminous “C ” range, while other western fuels tend to be categorized as higher rank bituminous or subbituminous coals. Figure 1 shows the criteria for ASTM’s coal rankings.

FIGURE 1 Coal ClassificationCOAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 3Most coals from the PRB are classified as Subbituminous “C” and demonstrate highreactivity and low-NO x production characteristics. Based on data from the Energy Information Administration (EIA), PRB coals currently represent 88 percent of total U.S. subbituminous production and 73 percent of western coal production. Most references to western coal and subbituminous coal infer PRB origin and characteristics. Emi ssions standards differentiating between bituminous and subbituminous coals are presume d to use PRB coal as the basis for the subbituminous standards, due to their dominant market presence and unique characteristics.



### Coal Characteristics Coal characteristics directly and significantly affect NO x emissions from coal combustion and play an important role in the ability to design and operate LNBs and OFA systems . As previously discussed, of paramount significance is the ability to control the introduct ion of air into the burner zone. Burner Zone Stoichiometry is the ratio of combustion air admit ted to the furnace versus the theoretical amount of air required for complete combustion. M ost units are designed to operate between 1.14 and 1.25 stoichiometry, where 1.0 is the theoretical amount of air required for combustion. When operating for low NO x , the Burner Zone Stoichiometry is reduced by the air staged through the OFA system. Aggress ive low- NO x firing systems typically are typically designed to operate with Burner Zone Stoichiometries less than theoretical (1.0).

Tests run by the boiler manufacturer ALSTOM showed the influence of both fuel type and stoichiometry on NO x emissions as illustrated in Figure 2. As expected, as the stoichiometry decreases, the percentage of the fuel NO x converted to NO x decreases. This testing also shows the trend that as the fuel rank decreases, the rate at which the fuel nitrogen c onverts to NO x also decreases.COAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 4 FIGURE 2 Nitrogen Conversion to NO x

0 10 20 30 40 50 60

BURN ER ZONE STOICHIOM ETRYFUEL BOUND NITROGEN CONVERSION L OW VOL

H I VOL A

H I VOL A

H I VOL B

H I-VOL C

SU BB IT C

L ower Higher

Subsequent testing in ALSTOM’s laboratory identified some of the key character istics of the coals and mechanisms for this nitrogen conversion efficiency. In general, the lower the fuel rank, the faster the coal is devolatilized and the faster the fuel NO x is released. Based on the chemical kinetics under staged conditions, nitrogen preferentially bonds together to for m inert molecular nitrogen N 2 instead of NO or NO 2 . Therefore, the more nitrogen that can be released earlier in the combustion process, the lower the NO x emissions can be. Low-rank coals show favorable behavior with regard to greater fuel nitrogen release during the devolatilization phases of the combustion process; this is conducive to greater NO x reduction. This is one of the reasons coals like PRB tend to react favorably to staged combustion, producing some of the lowest levels of NO x observed on U.S. coals.

The coals used at Bridger and Naughton tend to be higher rank than typical PRB coals. A s such, they will have less fuel nitrogen released during the devolatilization phas e of combustion, and thus will producehave somewhat higher NO x than will true PRB coals when fired under low-NO x staged conditions.

A second major factor in fuel NO x is related to how the fuel NO x evolves from the solid coal char that is produced once the volatile component of the coal is combusted. Generally speaking, approximately 20 to 40 percent of the fuel NO x can source from fuel-bound nitrogen associated with the solid char. Control of NO from this char nitrogen component cannot be directly controlled by air staging since under staged low-NO x combustion (reducing or pyrolysis conditions), char nitrogen conversion to NO remains relat ivelyCOAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 5 constant. Typically, lower rank (more reactive) fuels have more fuel NO x associated with the volatiles than the char, so low-rank coals overall have the lowest NO x potential.

The performance of the Bridger and Naughton coals tends to fall between the PR B coals and eastern bituminous coals shown. This would support the conclusion that the Bridger and Naughton coals have a NO x reduction potential below eastern bituminous coals, but not as low as true PRB coals.

This conclusion is supported by additional ALSTOM laboratory data shown in Figure 3. Testing in ALSTOM’s bench-scale Drop Tube Furnace can determine the r elative percentage of fuel NO x converted to NO x in both the devolatilization and char phases of combustion. It is clear that PRB coals can have greater than 78 percent of fuel NO x converted to NO x during devolatilization, which is far greater than that measured for bituminous coals. As a result of these observations, the performance of the Bridger and Naughton coals, in terms of total fuel NO x emissions would tend to fall between the PRB coals and eastern bituminous coals shown.

FIGURE 3 Fuel Nitrogen Conversion during Coal Devolatilizati on and Coal Char Combustion versus Coal Type



### Drop Tube Test Furnace Nitrogen Conversion versus C oal Type

78% 87% 83% 84%

58% 55%

31%

22%

13% 17% 16% 42% 45% 69%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

PRB PRB PRB PRB PRB & Bit. Blend Bituminous Bituminous% Fuel N to NOx During Devolatilization During Char Combustion

As previously mentioned, NO x formed by fixation of atmospheric nitrogen to oxygen (thermal NO x ) is the other main component of total NO x emissions for a boiler. The otherCOAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 6 two primary factors are unit design and operating procedures, and are therefore ve ry unit-specific. Unit design affects both the residence time of the combustion proce ss as well as the thermal aspects of combustion. Unit design determines how “hot” a furnace is, whi ch influences the thermal NO x contribution for both the baseline and post-retrofit NO x emissions. From its extensive retrofit experience, ALSTOM developed a s eries of thermal NO x prediction methodologies based on the physical unit dimensions and the thermal conditions firing eastern and midwestern fuels. These site-specific predic tive methodologies are used in combination with the fuel NO x prediction methodologies described above to make overall stack NO x emission predictions and commercial guarantees.

Figure 4 shows ALSTOM’s experience on coals from the west that rank either a s highvolatile bituminous B or C or as subbituminous B coals. The coals from Bridger and Naughton generally fall in these categories. Considering the data present ed in Figure 4, ALSTOM expects that the NO x emission levels of the Bridger and Naughton coals will be higher than those of PRB coals.

FIGURE 4 ALSTOM Experience on Western High Volatile Bitumino us B and C, and Subbituminous B

Average NOx Emissions as Reported by the EPA for the First Quarter of 200 4

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40

Level 1, Hi-vol B bit. Level 1, Hi-vol C bit. Level 3, Hi-vol C bit. Level 3, Hi-vol C bit. Level 3, Hi-vol C bit. Level 3, Subbit. B TFS 2000R, Subbit. C , ,

ALSTOM Low NOx System / Coal RankNOx, lb/mmBtu W estern Bituminous Sub-Bit B Sub-Bit CCOAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 7 As discussed previously, a number of western coals are classified as subbituminous ; however, they border on being ranked as bituminous and do not display many of the qualities of PRB coals, including most of the low-NO x -forming characteristics. The coals from the Bridger, Black Butte, Leucite Hills, and Naughton mines fall into this cat egory. As defined by ASTM, the only distinguishing characteristic that classif ies the coals used at Jim Bridger and Naughton as subbituminous rather than bituminous—that is, they are “nonagglomerating” as compared to “agglomerating.” While each of these coals is considered nonagglomerating, they either do not exhibit those properties of nonagglomerating coals or exhibit them to only a minor degree. Agglomerating as applied to coal is “the property of softening when it is heated to above about 400 degrees Celsuis (°C) in a nonoxidizing atmosphere, and then appearing as a coherent mass after cooling to r oom temperature.” Since the agglomerating property of coals is the result of part icles transforming into a plastic or semiliquid state when heated, it reflects a change in surfac e area of the particle. Thus, with the application of heat, agglomerating coals would tend to develop a nonporous surface while the surface of nonagglomerating coals would become even more porous with combustion. As shown by Figure 5, the increased porosity provides more particle surface area resulting in more favorable combustion conditions. This nonagglomerating property assists in making subbituminous coals more amenable to controlling NO x by allowing less air to be introduced during the initial ignition portion of the combustion process.

FIGURE 5 Illustration of the Effect of Agglomeration on the Speed of Coal CombustionCOAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 8 Table 1 compares key NO x -forming characteristics of the Bridger Mine, Black Butte, Leucite Hills, Naughton, a typical PRB coal, and Twentymile, a representative western bi tuminous coal.

TABLE1 NO x Characteristics Comparison

Parameter PRB Bridger Mine Black

Butte Leucite

Hills Naughton Twentymile

Nitrogen (% dry) 1.10 1.26 1.47 1.48 1.24 1.85

Oxygen (% dry) 16.2 13.2 13.4 13.2 15.4 7.19

Moisture (%) 27.3 19.1 20.7 19.0 20.9 9.85

Coal rank Sub C Sub A Sub A Sub A Sub A Bit high vo l B

As shown in Table 1, although Bridger, Black Butte, Leucite Hills, and Naughton are classified as subbituminous, they all exhibit higher nitrogen content, lower moist ure content, and lower oxygen content than the PRB coal. The higher nitrogen content is an indication that more nitrogen is available to the combustion process and higher NO x emissions are likely. Oxygen content can be correlated to the reactivity of the coal with more reactive coals—generally containing higher levels of oxygen. As previously stated, more r eactive coals tend to produce lower NO x emissions and are also more conducive to reduction of NO x emissions, through use of combustion control measures such as LNBs and OFA. These characteristics indicate that higher NO x formation is likely with Bridger, Black Butte, Leucite Hills, and Naughton rather than with PRB coal. The Bridger, Black Butte, Leuc ite Hills, and Naughton coals all contain quality characteristics that fall between a ty pical PRB coal and Twentymile, a clearly bituminous coal that produces higher NO x —as has been demonstrated at power plants burning Twentymile coal.

Using Jim Bridger 2 for illustrative purposes, Figures 6 and 7 graphically illus trate the relationship of nitrogen and oxygen content to related BART presumptive NO x limits for the coals listed in Table 1. Twentymile is used to graphically illustrate achie vement of the Best Available Retrofit Technoloaogy (BART) presumptive NO x limit for a bituminous coal and the PRB coal corresponds to the subbituminous BART presumptive NO x limit. The Bridger blend consists of a representative combination of coals from the Bridger Mine, Black B utte, and Leucite Hills that has been used at Jim Bridger 2, and indicates the average N O x emission rate achieved during 2003 to 2005. Jim Bridger 2 represents the NO x emission rate achieved after installation of ALSTOM’s current state of the art TFS2000 L NB and OFA System. This NO x emission level of 0.28 pound per million British thermal Units (MMBtu) corresponds to the BART presumptive limit for bituminous coal and underscores the difference in ability to reduce NO x while burning non-PRB subbituminous coals such as those from the Bridger Mine.

Figures 6 and 7 both demonstrate that with the TFS2000 low-NO x emission system installed and burning a combination of the Bridger, Black Butte, and Leucite Hill coals, the like ly NO x emission rate will be closer to the bituminous end (0.28) of the BART presumptive NO x limit range than to the BART presumptive NO x limit of 0.15 pound per MMBtu.COAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 9 PRB Subbituminous Twentymile Bituminous Bridger Blend

Jim Bridger 2

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

6.00 8.00 10.00 12.00 14.00 16.00 18.00 Typical Oxygen Content (%-Dry Basis)NOx Limit (lb/MMBtu)

Subbituminous Presumptive Limit - 0.15lb/MMBtu Bituminous Presumptive Limit - 0.28 lb/MMBtu FIGURE 6 Plot of Typical Nitrogen Content of Various Coals a nd Applicable Presumptive BART NO x Limits Jim Bridger 2

PRB Subbituminous Bridger Blend

Jim Bridger 2

Twentymile Bituminous

0.1 0.15 0.2 0.25 0.3 0.35 0.4 0.45

1.00 1.10 1.20 1.30 1.40 1.50 1.60 1.70 1.80 1.90 2.00 Typical Nitrogen Content (%-Dry Basis)NOx Limit (lb/MMBtu)

Bituminous Presumptive Limit - 0.28 lb/MMBtu

Subbituminous Presumptive Limit - 0.15 lb/MMBtu

FIGURE 7 Plot of Typical Oxygen Content of Various Coals and Applicable Presumptive BART NO x Limits Jim Bridger 2COAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN O XIDE FORMATION MEMO - FINAL.DOC 10 Coal quality characteristics also impact the design and operation of the boiler and associated auxiliary equipment. Minor changes in quality can sometimes be accommodate d through operational adjustments or changes to equipment. It is important to note, however, tha t consistent variations in quality or assumptions of “average” quality for perform ance projections can be problematic. This is particularly troublesome when dealing w ith performance issues that are very sensitive to both coal quality and combustion condit ions, such as NO x formation. There is significant variability in the quality of coals burned a t Jim Bridger and Naughton. For example, in addition to burning coal from Black Butte and Leucite Hills, Jim Bridger burns coal supplied from the Bridger Mine consis ting of three sources—underground, surface, and highwall operations. Each of these coal sources has different quality characteristics as well as inherent variability.

Several of the coal quality characteristics and their effect on NO x formation have been previously discussed. There are some additional considerations that illustrate the complexity of achieving and maintaining low NO x emissions with pulverized coal on a consistent, shorter term, such as a 30-day rolling average basis.

Good combustion is based on the “three Ts”: time, temperature, and turbulence. These parameters along with a “design” coal are taken into consideration when desi gning a boiler and associated firing equipment, such as fans, burners, and pulverizers. If a perform ance requirement such as NO x emission limits is subsequently changed, conflicts with other performance issues can result.

Jim Bridger is located at an altitude of 6,669 feet above sea level, and Naughton is at a n elevation of 6,396 feet above sea level. At these elevations, atmospheric pressure is lower (11.5 pounds per square inch) as compared with sea level pressure of 14.7 pounds per square inch. This lower pressure means that less oxygen is available for combustion for ea ch volume of air. To provide adequate oxygen to meet the requirements for efficient combust ion, larger volumes of air are required. When adjusting air flows and distribution to lower NO x using LNBs and OFA, original boiler design restrictions again limit the modifi cations that can be made and still achieve satisfactory combustion performance.

Another significant factor in controlling NO x emissions is the fineness of the coal entering the burners. Fineness is influenced by the grindability index (Hardgrove) of the coal. Finer coal particles promote release of volatiles and assist char burnout due to more surf ace area exposed to air. Nitrogen oxide reduction with high-volatile coals is improved with grea ter fineness and with proper air staging. The lower rank subbituminous coals such as PRB c oals are quite friable and easy to grind. Coals with lower Hardgrove Grindability Index values, such as those used at Jim Bridger and Naughton, are more difficult to grind and can contribute to higher NO x levels. In addition, coal fineness can deteriorate over time periods between pulverizer maintenance and service as pulverizer grinding surfaces wear.



### Conclusions Both laboratory data and field experience indicate that western low-rank fue ls are conducive to low-NO x firing. The laboratory data from carefully controlled small-scale expe riments has documented that the lower rank subbituminous C (PRB) and lignite coals typical of the we st will generate low-NO x due to the high volatility and quick yield of fuel bound nitrogen. The field experiences from these fuels match the predictions from the laboratory data. Based onCOAL QUALITY AND NITROGEN OXIDE FORMATION

JMS ES012009037SLC\BART COAL QUALITY AND NITROGEN OXIDE FORMATION MEMO - FINAL.DOC 11 ALSTOM’s experience to date, most other western subbituminous coals, such as those fired by PacifiCorp, will produce NO x levels somewhere between PRB coals and eastern bituminous coals.

For all of these reasons, the coals from the Bridger Mine, Black Butte, Leucite Hills, and Naughton mines used at the Jim Bridger and Naughton plants are more similar in their NO x formation potential to bituminous coals than to the subbituminous coals such as PRB. Therefore the presumptive BART limit that should be applied to the Bridger and Naughton plants should be closer to the 0.28 pound per MMBtu bituminous presumptive BART limit rather than the subbituminous 0.15 pound per MMBtu limit. This is also demonstrated by the actual performance of the LNB OFA TFS2000 low-NO x emission system installed on Jim Bridger Unit 2.



### Reference

ALSTOM, 2005. NO x Variation with Western U.S. Sourced Coals Fired in PacifiCorp Utility Boilers. Prepared for PacifiCorp. February 4.

The referenced text is included as Attachment 1.ATTACHMENT 1



# NO x 

# Variation with Western U.S. Sourced Coals

Fired in PacifiCorp Utility BoilersC:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc 

# NOx VARIATION WITH WESTERN U.S. SOURCED COALS FIRED IN PACIFICORP UTILITY BOILERS

Prepared For 

# PacifiCorp

February 4, 2005

Copyright 2005 ALSTOM All Rights Reserved

Confidential Attorney Client Communi cation and Attorney Work ProductC:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc This document has been carefully prepared by ALSTOM, Inc. It is based in part on observations and analysis, and any conclusions made in this document are based in part on experience and judgement. Another qua lified consultant mi ght reach different conclusions.

This document is provided only for the benefit of PacifiCorp, and not for the benefit of any third party.C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc



## NOx VARIATION WITH WESTERN U.S. SOURCED COALS FIRED IN PACIFICORP UTILITY BOILERS

ALSTOM, Inc Windsor, CT February 4, 2005

ABSTRACT

ALSTOM is a world leader in low NOx fi ring system technology, with over 380 boilers converted globally to low NOx firing on a wide range of coals. In the US, ALSTOM has provided low NOx firing systems to over 50 util ity boilers that fire Powder River Basin (PRB), lignite, and a variety of Western bitu minous and subbituminous coals. These units firing Western US coals accountfor over 21,000 MW of electrica l generation. From this extensive field experience, as well as fundame ntal laboratory study, it is clear that each western US coal has unique variations in chem istry and characteristics that directly affect combustion, NOx formation, and NOx reduction pot ential. As such, ALSTOM maintains that NOx emissions predictions for specific Western U.S. sourced coals must carefully consider the fundamental properties unique to each coal. This paper will focus on ALSTOM’s experience burning lignite, subbituminous a nd Western bituminous coals under low NOx conditions, and outline how NOx generated in West ern US coal fired utility boilers can be expected to vary signific antly based on each coal’s unique characteristics.



### NOx Formation Mechanisms

NOx formation and reduction in a utility boiler sources from the following three basic chemical mechanisms:

1) Thermal NOx

Thermal NOx, also known as Zel’dovich mechanism NOx, is formed from high temperatures (> 2700 F) in the combustion zo ne and furnace. Simply stated, nitrogen in the atmospheric air used for combus tion combines with oxygen at these high temperatures to form NOx. Thermal NOx can be affected exponentially by local temperatures and can be proportional to the square root of oxyge n availability. The key to minimizing thermal NOx is to stage fuel/air mixing in a controlled way, using low NOx firing systems and overfire ai r, to minimize excessive combustion temperatures. Boiler design, in terms of h eat transfer characteristics, also plays a major role in thermal NOx formation. For a retrofit application these design parameters are fixed by the boiler size and configuration, and cannot be easily changed. In a typical coal fired utility boile r, approximately 20% to 40% of the total NOx comes from thermal NOx.C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc 2) Fuel NOx

Fuel NOx is formed during combustion of fu els (like coal) containing inherent fuel bound nitrogen. Fuel NOx is affected by the total percentage of nitrogen contained in the coal, but there are other equally important factors. The release rate (reactivity) of nitrogen from volatile fractions of the coal in the early stages of combustion, and the nitrogen release rate from th e solid coal char (in the late r stages of combustion) have a direct impact on NOx. Coal chemistry factors such as coal porosity and fuel oxygen to nitrogen ratio also influence NOx formation. In addition, Fuel NOx can be affected by local oxygen availability. Lo w NOx firing systems reduce, but cannot eliminate fuel NOx generated from coal types that have high fuel NOx characteristics. In summary, coal chemical comp osition and physical properties all directly affect Fuel NOx, which typi cally represents approximately 60% to 80% of the total NOx from a coal fired utility boiler.

3) Prompt NOx

Prompt NOx, also known as Fenimore NOx, is formed by fractionation of hydrocarbons (CH) in the pr esence of atmospheric nitrogen (N2) when combusting fuels. Complex interactions between CH and N2 form HCN and N, which can combine with atmospheric oxygen and evol ve into additional NOx generated beyond thermal and fuel NOx mechanisms. Prompt NOx is normally less than 5 % of total NOx in coal fired boilers and can be controlled by optimized low NOx firing system design, as temperature and oxygen availability can affect hydrocar bon reaction rates.

This brief description of NOx formation funda mentals provides a simplistic overview of the NOx generation process. ALSTOM has a wide NOx experience base of over twenty years of R&D, including US Government-sponsored pr ojects, as well as designing and providing commercial Low NOx firing systems. It is ALSTOM’s position that these mechanisms interact in complex ways that are speci fic to each individual coal and boiler.

In the 1980’s ALSTOM began developing NOx prediction tools and design methods for firing eastern U.S. bituminous coals in order to provide commercial guarantees to utilities mandated to comply with the Clean Air Act of 1990. Some of these predictive tools are laboratory based, while others are based on compilation and an alysis of extensive field emissions data. In the 1990’s, electric utility units east of the Missi ssippi installed low NOx systems in response to the Clean Air Act Amendm ents. Many of these units, particularly in the Midwest, have since conve rted to Powder River Basin (PRB) coals for economic or sulfur emissions reasons. In the late 1990’s Texas regulations resulted in many PRB and lignite units being converted to low NOx firing. In addition to these units, other plants in Western states have or are in the process of implementing NOx controls. Many of these units are mine mouth units that fire coals that are unique to each unit. ALSTOM’s predictive methodology has evolved over the years as the unit experience base and ra nge of fuels tested has grown. These field experiences and furthe r laboratory testing of Western fuels have proven to ALSTOM that NOx emissions can va ry substantially between these differing Western coals.C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc 

### Western Coal Analysis and ASTM Rank

Coal is a complex fuel with wide variations in chemical analysis, physical characteristics, and combustion reactivity. The American So ciety for Testing Materials (ASTM) has developed a system for generally classifying coals based on their heating value, volatile content, moisture, reactivity and other pr operties. Eastern U.S. coals (high volatile bituminous) tend to be high rank fuels with hi gh heating values and low moisture. At the other end of the spectrum, U.S. lignite coals tend to be low ra nk, as their heating values are low, and moisture content high. Western U.S. coals, like Powder Ri ver Basin, tend to be categorized in the lower rank Subbituminous “C” range, while ot her Western fuels tend to be categorized as higher rank bitumi nous or subbitbuminous coals.

Coal from the Powder River Ba sin in Wyoming accounts for a pproximately 35% of the total coal production in the United States. Due to the significant amount of PRB fuel fired, ALSTOM has expended significant time and effort studying all aspects of the firing system and boiler effects from the combustion of these coal s. It is important to note that there are different mines within the PRB region, each with its own unique properties. The main focus of ALSTOM’s work on PRB coals has been on the mines south of Gillette, Wyoming, as these produce the largest volume of coal.

In the Western United States, the lignite fi elds in North Dakota and Texas combine to produce approximately 7% of the total coal mined in the US. Due to the high moisture and ash content, and subsequent low heating value, lignite is not economi cal to transport long distances. Therefore, all li gnite is consumed relatively close to the mine source.

E. bit. Hi-vol B bit. Hi-vol C bit. Sub bit. A Sub bit. B Sub bit. C TX Lignite

H 2 O 5.00 6.28 13.12 14.09 25.00 27.30 33.06 VM 33.10 37.49 34.91 33.75 32.43 31.90 26.75 FC 53.50 46.35 45.78 37.58 38.23 36.40 27.47 Ash 8.40 9.88 6.19 14.58 4.00 4.40 12.72 Hydrogen 5.00 4.68 4.22 4.12 3.72 3.49 3.02 Carbon 71.70 67.70 61.58 55.70 53.88 51.18 39.45 Sulfur 1.30 0.48 0.36 0.48 0.34 0.21 1.99 Nitrogen 1.60 1.38 1.23 0.98 0.72 0.73 0.67 Oxygen 7.10 9.60 13.30 10.05 12.32 12.71 9.09 HHV 12959 12000 10861 9674 9350 8800 6935

FC/VM 1.62 1.24 1.31 1.11 1.18 1.14 1.03 HHVdaf 14964 14313 13461 13562 13169 12884 12790 lb S/mmBtu 1.00 0.40 0.33 0.50 0.36 0.24 2.87 lb N/mmBtu 1.23 1.15 1.13 1.01 0.77 0.83 0.97 Ash Load 6.5 8.2 5.7 15.1 4.3 5.0 18.3

Table 1 - Typical Coal AnalysisC:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc There are also locally signifi cant coal fields in Utah, Co lorado, Montana, Wyoming, New Mexico, and Arizona. These fuels are also not transported as far as the coal from the Southern PRB. These coals rank between subbituminous A, B, and C and high volatile bituminous B and C. Combined, these six states account for approximately 15% of the total coal production in the US. Typical fuel analys es of various domestic ASTM ranked coals are shown in Table 1.

The coals fired at Jim Bridger Station are gene rally classified (ranked) by ASTM Standards as Western Sub-Bituminous “B” and “C” coals as seen on the attached Coal Classification Chart. Coals fired at Huntington Canyon are ge nerally ranked as high volatile “B” or “C” bituminous. Coals at Naughton are typically ranked as sub bituminous “B”. The coals fired at Hunter Station are classified as High Vola tile Bituminous “B” and “C”. Typical coal analyses are attached in Table 2 below.

Hunter Huntington Canyon Bridger Naughton 1&2 Naughton 3

H 2 O 8.56 9.95 19.1 20.8 21.1 VM 36.74 35.39 30.1 34.2 34.1 FC 44 47.11 40.4 40.6 39.7 Ash 10.71 7.55 10.1 4.5 5.2 Hydrogen 4.58 4.48 3.5 4.04 3.95 Carbon 64.12 65.3 54 56.87 55.78 Sulfur 0.4 0.33 0.6 0.56 1.1 Nitrogen 1.15 1.04 1.1 1.03 1.03 Oxygen 10.44 11.35 11.4 12.2 11.84 HHV 11489 11499 9428 10012 9900

FC/VM 1.2 1.33 1.34 1.19 1.15 HHV daf 14231 13938 13373 13403 13495 Ash Load 9.3 6.6 10.7 4.49 5.28

Table 2 - Coals Fired at PacifiCorp Stations

Several of the Pacificorp stations, such as Jim Bridger, are mine mouth plants and fire coals that are unique to those units. These coals ha ve very limited distribution outside of the specific plants, and as such, there are no operating low NOx systems firing these coals. Supporting data detailing the lim ited distribution of these coals is provided in the Appendix of this paper.

Comparing the above PacifiCorp co al analysis to that of the well-studied Power River Basin coals, it can be generally stated that these coals tend to be somewhat higher rank than PRB coals. It is expected that these fuels have somewhat different combus tion characteristics than PRB coals.C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc 

### Influence of Coal Analysis and Rank on NOx

Since over 60% of total stack NOx can be attr ibuted to fuel NOx, ALSTOM’s Power Plant Laboratory has studied the conversion of fuel bound nitrogen to NOx, as a function of fuel type and Burner Zone Stoichiometry. Burner Zone Stoichiometry is the ratio of combustion air admitted to the furnace versus the theo retical amount of air required for complete combustion. Most units are designed to ope rate between 1.14 and 1.25 stoichiometry, where 1.0 is the theoretical amount of air required for combustion. When operating for low NOx the Burner Zone Stoichiometry is reduced by the air staged through the Separated Overfire Air (SOFA) system. Aggressive low NOx firing systems typically are typically designed to operate with Burner Zone Stoichio metries less than theoretical (1.0).

This testing clearly showed the influence of both fuel type an d stoichiometry on NOx emissions as illustrated in Figure 1. As expected, as the stoichiometry decreases the percentage of the fuel bound nitr ogen converted to NOx decreases . This testing also shows the trend that as the fuel rank decreases, the ra te at which the fuel nitrogen converts to NOx also decreases.

Figure 1 - Nitrogen Conversion to NOx

Subsequent testing in the laborat ory identified some of the ke y characteristics of the coals and mechanisms for this nitrogen conversion efficiency. In general, the lower the fuel rank, , the faster the coal is devolatilized and the fa ster the fuel bound nitrogen is released. Based on the chemical kinetics under st aged conditions, nitrogen pref erentially bonds together to 0 10 20 30 40 50 60

BURNER ZONE STOICHIOMETRYFUEL BOUND NITROGEN CONVERSION LOW VOL

HI VOL A

HI VOL A

HI VOL B

HI-VOL C

SUBBIT C

Lower HigherC:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc form inert molecular nitrogen N 2 instead of NO or NO 2 . Therefore, the more nitrogen that can be released earlier in the combustion pro cess, the lower the NOx emissions can be. Low rank coals show favorable behavior with regard to greater fuel nitr ogen release during the devolatilization phases of the combustion pro cess; this is conducive to greater NOx reduction. This is one of the reasons coals like PRB tend to react favorably to staged combustion, producing some of the lowest le vels of NOx observed on U.S. coals. The PacifiCorp coals tend to be higher rank than typical PRB coals. As such, they will have less fuel nitrogen released during devolatilizat ion, and thus will have somewhat higher NOx than true PRB coals when fired under low NOx staged conditions.

A second major factor in fuel NOx is related to how the fuel bound nitrogen evolves from the solid coal char that is produced once the volatile component of th e coal is combusted. Generally speaking, approximately 20-40% of the Fuel NOx can source from fuel bound nitrogen associated with the solid char. C ontrol of NO from this char nitrogen component cannot be directly controlled by air stag ing since under staged low NOx combustion (reducing or pyrolysis conditi ons), char nitrogen conversi on to NO remains relatively constant. Typically, lower rank (more reactiv e) fuels have more fuel bound nitrogen associated with the volatiles than the char, so low rank coals overall have the lowest NOx potential.

Figure 2 - Air Burnoff of PRB Coals and Reference Coals Air Burnoff of 200x400 Mesh PRB Project Coals

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0

200 250 300 350 400 450 500 550 600 650 Temperature ( o C)Burnoff Rate, -dW/dt (relative) SPRB 3

NPRB

BSF Cordero Rojo

SPRB 2

PRB Blend

SPRB 5

SPRB 1

Sub Bit

BSF Viking, hvCb

North Cambria East Bit 1

East Bit 2 SPRB 4 PRB Sub Bit. C

Eastern Bit.C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc In order to better understand how fuel bound nitrogen in both the volatile and char components of different rank coals affects tota l NOx reduction potential, coals and their char components are tested in a laboratory inst rument known as the Thermal Gravimetric Analyzer, or TGA. Under this analysis the bur n-off rate (change in weight/unit time) for various coals or coal chars can be shown as a function of temperature. An example of a TGA analysis for a wide variety of coals in shown in Figure 2. As can be seen, all of the PRB coals tested have similar rapid burn-off ra tes as compared to bituminous coals. This indicates that low rank PRB coals potentially have high volatile fuel nitrogen conversion rates and therefore lower NOx potential as compar ed to high rank Eastern bituminous coals. The performance of the PacifiCorp coals tends to fall between the PRB coals and Eastern bituminous coals shown. This would support the conclusion that the PacifiCorp coals have a NOx reduction potential well below Eastern bituminous coals, but not as low as true Powder River Basin coals.



### Drop Tube Test Furnace Nitrogen Conversion versus Coal Type

78% 87%

83% 84%

58% 55%

31%

22%

13% 17% 16% 42% 45% 69%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%

PRB PRB PRB PRB PRB & Bit. Blend Bituminous Bituminous% Fuel N to NOx During Devolatilization During Char Combustion

Figure 3 - Fuel Nitrogen Conversion During Coal Devolatilization and Coal Char Combustion versus Coal Type

.C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc This conclusion is supported by additional AL STOM laboratory data shown in Figure 3. Testing in ALSTOM’s bench scale Drop Tube Fu rnace can determine the relative percentage of fuel bound nitrogen converted to NOx in both the devolatilization and char phases of

. combustion. It is clear that PRB coals can have greater than 78% of fuel bound nitrogen converted to NOx during devolatilization, whic h is far greater than that measured for bituminous coals. As a result of these observatio ns, the performance of the PacifiCorp coals, in terms of total fuel NOx emissions would tend to fall between the PRB coals and Eastern bituminous coals shown.

As mentioned earlier, NOx formed by fixati on of atmospheric nitrogen to oxygen (thermal NOx) is the other main component of total NOx emissions for a boiler. The other two primary factors are unit design and operating pro cedures, and are therefor e very unit specific. Unit design affects both the reside nce time of the combustion pro cess, as well as the thermal aspects of combustion. Unit design determines how “hot” a furnace is, which influences the thermal NOx contribution for both the baseline and post-retrofit NOx emissions. From its extensive retrofit experience, ALSTOM deve loped a series of thermal NOx prediction methodologies based on the physical unit dime nsions and the thermal conditions firing Eastern and Midwestern fuels. These site-s pecific predictive met hodologies are used in combination with the fuel NOx prediction me thodologies described a bove to make overall stack NOx emission predictions and commercial guarantees.



### Field Experience with Western U.S. Coals

To date, ALSTOM has retrofitted over 50 units firing Western U.S.coals since 1995. Tangentially fired units burning low rank fu els consistently produce the lowest NOx emissions levels in the c ountry on a yearly basis.

Figure 4 shows the experience on coals from th e West that rank eith er as high volatile bituminous B or C or as subbituminous B coals. The coals that PacifiCorp is currently firing generally fall in these categories. Consider ing the data presented in Figure 4, the NOx emission levels of the PacifiCorp coals will be higher than those of PRB coals.

A recently published ALSTOM technical paper on Western coal firing experience is attached in the Appendix section of this paper. Th is technical paper was presented at the EERC Western Fuels Symposium in 2004.C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc Figure 4 – ALSTOM Experience on Western high volatile bituminous B and C, and subbituminous B



### CONCLUSIONS

Both laboratory data and field experience indicate that Western low rank fuels are conducive to low NOx firing. The laboratory data from carefully controlled small scale experiments has documented that the lower rank subbituminous C (PRB) and lignite coals typical of the West will generate low NOx due to the high vola tility and quick yield of fuel bound nitrogen. The field experiences from these fuels match the predictions from the laboratory data. Based on ALSTOM’s experience to date, most other We stern bituminous coals such as those fired by PacifiCorp will produce NOx levels somewhere between PRB coals and Eastern bituminous coals. Average NOx Emissions as Reported by the EPA for the First Quarter of 2004

0.00 0.05 0.10 0.15 0.20 0.25 0.30 0.35 0.40

Level 1, Hi-vol B bit. Level 1, Hi-vol C bit. Level 1, Hi-vol C bit. Level 3, Hi-vol C bit. Level 3, Hi-vol C bit. Level 3, Hi-vol C bit. Level 3, Subbit. B Level 3, Subbit. B TFS 2000R, Subbit. C ALSTOM Low NOx System / Coal RankNOx, lb/mmBtu Western Bituminous Sub-Bit B Sub-Bit CC:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc 

### APPENDIX

List of Contents

A. PacifiCorp Coal Supply Data B . “ALSTOM’s Low NOx Firing Experience on Western Fuels” , Jennings, Patrick and Hart, Doug. Presented at EERC Western Fuels Symposium, 2004

A PacifiCorp Coal Supply

The PacifiCorp units that are located in Wyom ing and Utah include the following sites with ALSTOM “Tangential –fired” boilers:

Wyoming Units Dave Johnston Station Jim Bridger Station Naughton Station

Utah Units Carbon Station Hunter Station Huntington Canyon Station

The coals fired at the Jim Bridger and Naughton Stations are classified as Sub-Bituminous “B” coals while the coals fired at Dave Johns ton Station as Sub-Bituminous “C” form the Powder River Basin. The coals fired at Ca rbon, Hunter and Hunti ngton Canyon Stations are classified as high Volatile “C” to hi gh Volatile “B” Bituminous coals.

The coal data below is from “ RDI – Coal.dat ” (U.S. Plants and Coal Sources). This data will show that Jim Bridger Station and Naughton Station are the prominent users of the coals that are fired at these stations, while the othe r units fire coals that are used at multiple locations.

Jim Bridger Station

The coal that has been fired at Jim Bridge r Station since 2000 come s from the following mines in Sweetwater County, WY:

Jim Bridger Black Butte & Leucite Hills

The other plants that have received coal form these mines are:

Naughton Station - 454,000 tons in 2000 North Valmy Station – 68,000 tons in 2001C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc Naughton Station

The coal that has been fired at Naughton St ation since 2000 comes from the following mines in Lincoln County, WY a nd Sweetwater County, WY:

Kemmerer (Elkol & Sorenson) Black Butte & Leucite Hills – 454 tons in 2000.

No other plants are listed as receiving co al from the mines in Lincoln County, WY

Carbon Station The coal that has been fired at Carbon Sta tion since 2000 comes from the following mines in Emery County, Carbon and Sevier Counties in UT:

Deer Creek (C) Crandall Canyon Bear Canyon No. 2 Bear Canyon No. 1 Sufco Skyline No. 3 Dug Out Whiskey Creek (Synfuel) West Ridge

The other plants that have received 50,000 or more tons of coal from these mines from 2000 or later are:

Hunter – PacifiCorp (UT)* Huntington Canyon – PacifiCorp (UT)* Grand River Terminals –TVA (IL) Asbury – Empire District Electric Co. (MO) Cora Transfer Terminal – TVA (IL) Genoa – Dairyland Power Coop (WI) * Intermountain Generating – Los Angele s Dept. of Water and Power (UT) Sibley – Aquila (MO) Boardman – Portland General Electric – (OR) ACE Cogeneration – Ace Cogeneration Co. (CA) Argus – IMC Chemicals – (CA) * Edgewater – Wisconsin Power & Light – (WI) Gardner – Nevada Power Co. – (NV) Michigan City – Northern Indi ana Public Service Co. - (IN) North Valmy – Sierra Pacific Power Co. – (NV) Stockton CoGen Co. – Air Products & Chemicals, Inc. - (CA) Alma - Dairyland Power Coop - (WI) J.P. Madgett - Dairyland Power Coop – (WI) Manitowoc – Manitowoc Public Utilities – (WI) Mount Poso Cogeneration – M ount Poso Cogeneration (CA)C:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc Hunter Station

The coal that has been fired at Hunter Stat ion since 2000 comes from the following mines in Emery County, Carbon and Sevier Counties in UT:

Deer Creek (C) Trail Mountain Dug Out Sufco West Ridge

The other plants that have received 50,000 or more tons of coal from these mines from 2000 or later are:

Carbon Station – PacifiCorp (UT)* Huntington Canyon Station – PacifiCorp (UT)* Grand River Terminals –TVA (IL) Asbury Station – Empire District Electric Co. (MO) Cora Transfer Terminal – TVA (IL) Genoa Station – Dairyland Power Coop (WI)* Intermountain Generating – Los Angele s Dept. of Water and Power (UT) Sibley Station – Aquila (MO) Boardman Station – Portland General Electric – (OR) ACE Cogeneration – Ace Cogeneration Co. (CA) Argus – IMC Chemicals – (CA)* Edgewater Station – Wisconsin Power & Light – (WI) Gardner Station – Nevada Power Co. – (NV) Michigan City Station – Northern Indiana Public Service Co. – (IN) North Valmy Station – Sierra Pacific Power Co. – (NV) Stockton CoGen Co. – Air Products & Chemicals, Inc. – (CA) Alma Station – Dairyland Power Coop – (WI) J.P. Madgett - Dairyland Power Coop – (WI) Manitowoc – Manitowoc Public Utilities – (WI) Mount Poso Cogeneration – M ount Poso Cogeneration (CA)

Huntington Canyon Station

The coal that has been fired at Hunti ngton Canyon Station since 2000 comes from the following mines in Emery County, Carbon and Sevier Counties in UT:

Deer Creek (C) Emery Dug Out Sufco West RidgeC:\Documents and Settings\tsturdav.CH2MHI LL\My Documents\Mail\OL Temp Attachme nts\1 - PacifiCorp Coals Paper 2-04-05 Final.doc The other plants that have received 50,000 or more tons of coal from these mines from 2000 or later are:

Carbon Station – PacifiCorp (UT)* Hunter Station – PacifiCorp (UT)* Grand River Terminals –TVA (IL) Asbury Station – Empire District Electric Co. (MO) Cora Transfer Terminal – TVA (IL) Genoa Station – Dairyland Power Coop (WI)* Intermountain Generating – Los Angele s Dept. of Water and Power (UT) Sibley Station – Aquila (MO) Boardman Station – Portland General Electric – (OR) ACE Cogeneration – Ace Cogeneration Co. (CA) Argus – IMC Chemicals – (CA)* Edgewater Station – Wisconsin Power & Light – (WI) Gardner Station – Nevada Power Co. – (NV) Michigan City Station – Northern Indiana Public Service Co. – (IN) North Valmy Station – Sierra Pacific Power Co. – (NV) Stockton CoGen Co. – Air Products & Chemicals, Inc. – (CA) Alma Station – Dairyland Power Coop – (WI) J.P. Madgett - Dairyland Power Coop – (WI) Manitowoc – Manitowoc Public Utilities – (WI) Mount Poso Cogeneration – M ount Poso Cogeneration (CA)

* ALSTOM, Inc. - “Tangential-fired” units

Dave Johnston Station

The coal fired at Dave Johnston Station is a sub-bituminous coal from the Powder River Basin (PRB). This coal is fire d at numerous units that fire the coals from the PRB region:

Dave Johnston receives coal from th e following mines since the year 2000:

Black Thunder Coal Creek Cordero (Caballo Rojo) Dave Johnston Dry Fork Wyodak Jacobs Ranch Caballo Buckskin Rawhide

There are many units that fire coals from the PRB region.